Natural gas which is produced from a natural gas well is usually separated and purified to provide products for a variety of end uses. The high-pressure mixture produced from the well, i.e. the wellstream, is typically sent to a separator vessel or a series of separator vessels maintained at progressively lower pressures where the wellstream is separated into a gaseous fraction and a liquid fraction.
The gaseous fraction leaving the separator, which may contain impurities such as mercury, carbon dioxide and hydrogen sulfide, is sent to a gas treatment and purification plant where the mercury concentration is normally reduced to &lt;0.1 micrograms/Nm.sup.3, the CO.sub.2 concentration is reduced to the parts per million (ppm) level, and the H.sub.2 S to about one (1) ppm.
The purification of the gaseous fraction is commonly achieved by passing the gaseous fraction over a bed of activated carbon which has been impregnated with sulfur. In this step, the mercury in the gas reacts with the sulfur and is essentially removed from the gaseous fraction. The mercury content of the gas can be reduced from about 250 micrograms/Nm.sup.3 or higher to less than about 0.1 micrograms/Nm.sup.3.
The gas leaving the sulfur/carbon bed then could be treated with a hot aqueous potassium carbonate solution which has the ability to absorb CO.sub.2 and H.sub.2 S. This step produces a natural gas stream having a reduced CO.sub.2 and H.sub.2 S content. For example, the CO.sub.2 content of the gas can be reduced from about 15% to about 0.3% and the H.sub.2 S content from about 80 ppm to about 6 ppm.
The natural gas stream which resulted from treatment with the carbonate solution is further treated in order to reduce the amount of CO.sub.2 and H.sub.2 S by treating the gas with an amine solution, e.g. an aqueous solution of diethanolamine. Diethanolamine has the ability to absorb CO.sub.2 and H.sub.2 S, and can reduce the CO.sub.2 content from about 0.3% to about 50 ppm, and the H.sub.2 S content from about 6 ppm to about 1 ppm. The natural gas is then washed with water to remove traces of entrained amine. This water wash, however, neither removes residual mercury (typically present in levels of less than 0.1 .mu.g/Nm.sup.3) nor residual H.sub.2 S and CO.sub.2 (typically about 1 ppmv and 50 ppmv) respectively.
The washed natural gas is water-saturated and has to be dried prior to liquefaction. Usually drying is achieved by contacting the wet gas with a desiccant in a parked bed specifically designed for this purpose. The desiccant bed undergoes repeated cycles of adsorption and regeneration. To ensure that the desiccant bed retains its integrity during the drying and regeneration cycles, a protective layer of inert alumina spheres having a depth of about 0.5-2 ft. is placed over the desiccant. The alumina spheres in the protective layer are somewhat larger than the desiccant particles.
The dried gas, which still contains small amounts of mercury, CO.sub.2 and H.sub.2 S, can be further purified by contacting it with an adsorbent bed comprising sulfur on carbon, which has the ability to selectively remove mercury from the gas. Usually such an adsorbent can reduce the mercury, concentration to less than about 0.01 .mu.g/Nm.sup.3. However, including such an additional bed causes a pressure drop in the system, which is undesirable in a system where elevated pressure is required for maximum efficiency.
Thus, it would be beneficial to provide a mechanism for further reducing the level of residual mercury from the gas leaving the desiccant bed without the additional pressure reduction resulting from the use of a second adsorbent bed. It would also be very desirable to remove residual CO.sub.2 and H.sub.2 S from the gas.
It is therefore an object of the present invention to provide an improved method for reducing residual levels of mercury from a gas stream.